This invention relates to improvements in hydroprocesses, such as hydrocracking and hydrotreating processes, used in refinery operations to produce middle distillates, including jet and diesel fuels.
In processes for the catalytic conversion of a hydrocarbon feed stock, the step of recycling a hydrogen-rich vapor or gas phase separated from the reaction zone effluent is common. Practical reasons for utilizing this step reside in maintaining both the activity and operational stability of the catalyst used in the process. In hydrogen producing processes, such as catalytic reforming, hydrogen in excess of that required for the recycle feed stream is recovered and utilized in other processes integrated into the overall refinery. For example, the excess hydrogen from a catalytic reforming unit is often employed as the makeup hydrogen in a hydrocracking process, where the reaction principally is hydrogen-consuming.
Regardless of the particular process, the recycled hydrogen is generally obtained by cooling the total reaction product effluent to a temperature in the range of from about 60xc2x0 F. (15.6xc2x0 C.) to about 140xc2x0 F. (60xc2x0 C.), and introducing the cooled effluent into a vapor-liquid separation zone. The recovered vapor phase required to satisfy the hydrogen requirement of the reaction zone is recycled and combined with the hydrocarbon feed stock upstream of the reaction zone.
The art has long recognized the importance of improving the purity of the hydrogen in the recycle stream of hydroprocessors, such as hydrocracking and hydrotreating units. Thus, it has been the goal of the art to provide enhanced efficiencies of hydrogen utilization with little additional energy consumption and without undue deleterious effects on the maintenance or operation of the hydrocracking equipment. It has also been recognized that by increasing the efficient use of hydrogen, existing equipment could be employed to increase the throughput of the feed stock and also increase the yield of C5 and higher hydrocarbons. A further obvious advantage to the more efficient utilization of hydrogen is the reduction in the amount of hydrogen that must be produced by, for example, a hydrogen plant to ensure that the hydroprocessing zone has sufficient hydrogen of adequate purity to enable the hydroprocessing to proceed in the most advantageous manner. See, for example U.S. Pat. No. 4,362,613 issued Dec. 7, 1982 to Monsanto Company.
In a conventional hydrocracking process, a heavy vacuum gas oil (VGO), which may be additionally mixed with demetalized oil (DMO) or coke-gas oil, is mixed with hydrogen gas to form a feed stream that is introduced under pressure into the top of a catalytic reactor. The VGO liquid and gaseous hydrogen mixture passes downwardly through one or more catalyst beds. The higher the partial pressure of hydrogen in the feedstream to the reactor, the greater will be the efficiency with which the heavier hydrocarbon feedstock is converted to the desired lighter middle distillate products, such as jet fuel and diesel fuel.
After passing through the catalyst, the hot reactor effluent is cooled and passed to a high pressure separator from which the liquid product stream is removed and, if desired, can be subjected to further fractionation.
The flash gases from the HP separator contain hydrogen and C1 to C5 hydrocarbons. These flash gases can contain for example from about 78 to up to 82 mole-percent (mol %) of hydrogen. In the conventional processes of the prior art, the flash gases are combined with a makeup hydrogen stream that is typically available at 96 to 99.99 mol % purity. The recycle gas and, if necessary, the makeup hydrogen streams are compressed and combined with the liquid feed stock at the inlet of the hydrocracking reactor. A portion of up to 2% of the flash gases from the high pressure separator are purged to the refinery fuel gas system to prevent the build-up of the light hydrocarbon products in the reactor gas recirculation loop.
If the heavy VGO feed is sour, i.e., it contains sulfur, the separated effluent gas stream will contain H2S in addition to the hydrogen and C1 to C5 hydrocarbons. In order to prevent build-up of H2S in the reactor gas recirculation loop, the flash gases are contacted with an amine solution to remove the H2S and to sweeten the gas stream. A portion of the sweetened low pressure flash gases are purged to the refinery fuel gas system to prevent build-up of C1 to C5 hydrocarbons in the reactor gas recirculation loop. The remaining sweetened recirculated gases are combined with makeup hydrogen, compressed and passed to the reactor inlet as part of the hydroprocessor feed. Depending upon the H2S content of the sour gas exiting the reactor, the hydrogen concentration of the sweetened recirculation gas stream can be increased to for example from 80 to 84 mol % hydrogen.
The type of feedstock to be processed, product quality requirements, and the amount of conversion for a specific catalyst cycle life determine the hydrogen partial pressure required for the operation of both types of hydroprocessing units, i.e., hydrocracker and hydrotreater units. The unit""s operating pressure and the recycle gas purity determine the hydrogen partial pressure of the hydroprocessing unit. Since there is limited control over the composition of the flashed gas from the downstream HP separator, the hydrogen composition of the recycle flash gas limits the hydrogen partial pressure ultimately delivered to the hydroprocessing reactor. A relatively lower hydrogen partial pressure in the recycle gas stream effectively lowers the partial pressure of the hydrogen gas input component to the reactor and thereby adversely affects the operating performance with respect to distillate quantity and quality, catalyst cycle life, heavier feed processing capability, conversion capability and coke formation. To offset the lower performance, the operating pressure of the hydroprocessing reactor has to be increased. Conversely, by increasing the efficiency of hydrogen gas recovery and hydrogen composition, the hydrogen partial pressure of the recycle gas stream improves thereby improving the overall performance of the hydroprocessing reactor as measured by these parameters.
In the practice of the prior art processes, there are only four ways known to improve the hydrogen partial pressure in the hydrocracker or hydrotreater unit. These are as follows:
1. increasing the hydrogen purity of the makeup stream from the hydrogen unit;
2. purging or venting gas from the high-pressure separator;
3. reducing the temperature at the high-pressure separator to decrease the entrainment of light hydrocarbons in the recycle gas, and
4. improving the hydrogen purity of recycle gas.
All of foregoing methods have a very limited capability for improving the performance of an existing unit. If the hydrogen plant optimizes the purity of the makeup hydrogen, it will be in the 96 to 99 mol % range. Since the high purity H2 makeup flow rate is typically only about one-third or less of the total combined hydrogen fed to the hydroprocessing reactor through recirculation of flashed recycle gas, the overall improvement in the H2 purity or concentration of the combined recycle and makeup gas streams is limited.
Purging or venting gases from the HP separator will result in the loss of some of the hydrogen in the circuit which must eventually be replaced, thereby putting a greater demand on the hydrogen production unit. The extent to which the separator temperature can be lowered is limited by nature of the process and this change has, in any event, a relatively minor effect on recycle gas H2 purity.
It has been recognized that unlike most hydrocarbon gases, hydrogen has the unique property of increasing its solubility in hydrocarbon liquids with increasing temperature. For example, the solubility of hydrogen in a particular oil at 900xc2x0 F. (482.2xc2x0 C.) can be five times as great as its solubility in the same oil at 100xc2x0 F. (37.8xc2x0 C.). This characteristic is utilized in a process disclosed in U.S. Pat. No. 3,444,072 to Lehman, where the loss of hydrogen dissolved in the liquid effluent from a high-pressure hydrogenation unit is minimized by separating the vapor effluent from the liquid effluent at approximately reaction temperature and pressure, and subsequently flashing the liquid effluent at substantially reaction temperature, but at a lower pressure. The gaseous effluent stream is cooled to ambient temperatures and then contacted in an absorber where it contacts absorber oil in counter-current flow. It is specifically stated that the absorber oil is not subsequently flashed because at ambient temperature the solubility of hydrogen in the absorber oil is not significant, as compared to the overall volumes of hydrogen in the operating system. The overhead absorber gas stream reportedly contains 70-80 volume % hydrogen, which is returned to the reactor in the recycle gas stream and combined with makeup hydrogen. The limited improvement offered by Lehman does not significantly change the hydrogen partial pressure.
Although a variety of processes have been proposed and adopted that are intended to improve the hydrogen utilization efficiency by increasing the purity of the hydrogen in the recycle gas stream, these processes typically result in significant additional equipment costs and/or require significant changes in operating conditions, such as temperature and pressure. The result of changes to the overall process cycle is increased capital and operating expenses.
One process that has been adopted to improve the hydrogen purity of the recycle stream is pressure swing adsorption (PSA). See, for example, U.S. Pat. No. 4,457,384 issued Jul. 3, 1984 to Lummus Crest, Inc. However, in order to incorporate the PSA process, the pressure of the reactor effluent gas stream must be reduced from 2,450 psig (172.2 kg/cm2g) to 350 psig (24.6 kg/cm2g). Although the purity of the recycle hydrogen can be increased to 99 mol %, the recycled gas must be subjected to compression to return it to 2,500 psig (175.8 kg/cm2g) before introduction into the hydroprocessor feed stream. The net result is that the capital, operating and maintenance costs are substantially increased by the addition of a large compressor that is required in the PSA process.
Prior art processes as described in U.S. Pat. No. 4,362,613 to MacLean have used membranes with pressure drops up to 150 atmospheres which incur substantial capital investment and operating costs.
It is therefore an object of this invention to provide an improved process for enhancing the efficiency of hydrogen utilization by means that are compatible with particular existing hydroprocessing units and that does not adversely affect the hydroprocessing throughput or the overall economies of the system, including capital expenditures and operating expenditures, the latter including maintenance and energy consumption.
As previously noted, the overall operating efficiency of the hydroprocessing reactor can be increased if the partial pressure of hydrogen gas in the feed to the reactor can be increased. It is therefore another object of the present invention to improve the operating performance of hydroprocessing units by increasing the through-put capacity of existing hydrocracking and hydrotreating reactors.
Another object of this invention is to improve the operating characteristics for hydrotreating and hydroprocessing in refinery units handling heavier oils.
A further object of this invention is to provide for the enhanced efficiency of hydrogen utilization in high pressure hydrogenation process while minimizing capital expenditures for additional equipment and their related operating expenses.
It is yet another object of this invention to enhance the quality and production rate of low-sulfur middle distillates, such as jet and diesel fuels, obtained from hydroprocessing units operated in accordance with the invention.
As used herein, the terms xe2x80x9chydrogen-richxe2x80x9d and xe2x80x9cC1+xe2x80x9d are intended to represent relative hydrogen and C1+ concentrations in a particular stream in comparison to the hydrogen and C1+ concentrations in other streams in the process of the present invention.
The terms xe2x80x9chydroprocessingxe2x80x9d and xe2x80x9chydroprocessorxe2x80x9d are to be understood to include hydroprocesses such as hydrotreating, hydrocracking, hydrodesulfurization, hydrodenitrogenation and hydrodealkylation reactors.
The improved process of this invention can be employed with hydrotreating, hydrocracking, hydrodesulfurization, hydrodenitrogenation and hydrodealkylation reactors. In the improved process for a hydrocracking unit, the flash gases from the high-pressure separator (HP Separator) are fed to the bottom of an absorption zone where the entering gases are counter-currently contacted with a lean solvent. The lean solvent absorbs away the contained methane, ethane, propane, butanes and pentanes (C1+) from the contained hydrogen. The overhead gas stream from the absorption zone typically contains hydrogen at a purity of 90 to 98 mol %, or even higher.
The partial pressure of hydrogen in the recycle gas stream is significantly improved with hydrogen purity in the range of 96 to 99 mol % by absorption of the hydrocarbon components (C1+) from the HP Separator flash gas stream. The increase in hydrogen partial pressure of the hydrogen gas input component to the hydrocracker results in an increase in the overall efficiency of the hydroprocessor unit.
The rich solvent from the absorption zone containing the C1+ components present in the HP Separator flash gas stream is flash regenerated to form lean solvent in accordance with U.S. Pat. Nos. 4,740,222; 4,832,718, 5,462,583, 5,546,764 and 5,551,972, the disclosures of which are herein incorporated by reference. The lean solvent, comprises predominantly the heavier C4 to C5 hydrocarbons and is returned to the top of the absorption zone (methane absorber).
It is known to the prior art from the description of the Mehra Process(copyright) disclosed in U.S. Pat. No. 5,551,972, and others, that the inventory of lean liquid solvent that is required to supply the feed to the absorption zone can be maintained and stabilized by controlling the temperatures at the exit of the liquid coolers. Thus, by monitoring solvent inventory, the volume of the liquid solvent stream lost due to equilibrium at the operating conditions within the absorption zone from lean solvent stream entering the absorption zone is made equal to the C4 to C5 components present in the HP Separator flash gas stream. By maintaining this balance, no makeup solvent is required to replenish the inventory once the process has reached steady-state operating conditions.
Some important advantages of utilizing the Mehra Process in the process of the present invention relate to savings in capital and operating costs. The liquid solvent is regenerated by flashing the absorption zone bottoms stream to reduce pressure in one or more flash drums connected in series, with no external heat added. After the initial batch of solvent charged to start up the process of the invention, no external solvent is required, since the absorption solvent consists predominantly of heavy components supplied by, or present in the hydrocarbon feed to the absorption zone.
Elimination of the need to introduce external solvent to the hydroprocessor system eliminates the possibility of contamination of the reactor feed and catalyst. It further reduces capital investment and operating costs since solvent storage, pumping and metering facilities are not required. The costs and equipment associated with buying, receiving, storing and charging makeup solvent are also eliminated. These advantages and cost savings are particularly significant for hydroprocessing units located in remote areas.
When the heavier liquid hydrocarbon feed to the hydrocracker contains sulfur compounds, the effluent H2S present in the flash gases from the HP Separator are also absorbed away along with the C1+ components from the H2 recycle gas stream and carried away in the rich solvent stream from the absorption zone. The absorbed gases present in the rich solvent from the absorption zone are separated in the solvent flash regeneration drums of the Mehra Process and contain H2S. Contained H2S in the separated sour C1+ components stream can be conveniently removed by amine treating in a significantly smaller treating unit. By comparison to known methods of the prior art, this invention requires a significantly smaller amine treating unit than would be required in the conventional process for treating the flash gas stream from the HP Separator. This is because the volume of gas containing the hydrogen sulfide has been greatly reduced by the prior separation and removal of the hydrogen component.
In accordance with the process of this invention, the hydrogen partial pressure of the recycle gas is increased. In a typical unit operation utilizing the process of this invention, the hydrogen concentration can be increased from about 84 mol % achieved in the prior art processes, to a value of from 90 to 99 mol %, or even higher. This improvement is equivalent to a 6 to 15 mol % increase in hydrogen purity. In units which operate at around 2,400 psig (168.7 kg/cm2g), for a 13 mol % increase in hydrogen purity, the increase in hydrogen partial pressure is around 312 psi (21.9 kg/cm2). This increase in the recycle gas purity attributable to the practice of the method of the present invention produces the following advantages in the unit""s operation:
1. higher product yields;
2. better distillate quality;
3. longer catalyst cycle life;
4. heavier feed processing capability;
5. higher conversion capability;
6. prevention of coke formation; and
7. improved feed distribution over catalyst bed.
The significance and effect of these advantages will be further discussed in the context of a hydrocracking unit.
11 Higher Product Yields
Operating at higher hydrogen partial pressures will result in lower start-of-run (SOR) temperatures, and a lower average bed temperature throughout the cycle. Doing so will increase the liquid product yield by about 4% and reduce lower-value gas make.
2. Better Distillate Quality
Higher hydrogen partial pressure improves the jet, diesel and unconverted oil quality. The estimated improvement in product quality by increasing the hydrogen partial pressure by 312 psi (21.9 kg/cm2) is estimated as follows:
a. Cetane Number improved by about 3 to 4; and
b. Aniline point improved by about 13xc2x0 F. (7.2xc2x0 C.) to 17xc2x0 F. (9.4xc2x0 C.).
3. Longer Catalyst Cycle Life
Higher hydrogen partial pressure results in an increase in the catalyst cycle life. The catalyst cycle life is determined for any given unit by the Start of Run (SOR) and the End of Run (EOR) temperature and the deactivation rate of the catalyst. SOR temperature is a function of the catalyst activity, unit pressure and the type of feed being processed. The catalyst cycle life is also a function of catalyst stability, which is measured in terms of deactivation rate (xc2x0 C. or xc2x0 F. per month). EOR temperature is determined by the reactor""s metallurgy or the unit""s economics (yield). Increasing the hydrogen partial pressure b)y 312 psi (21.9 kg/cm2) produces the following benefits:
a. Improved catalyst stability (relative deactivation rate) by about 70%. This is a major improvement for the catalyst cycle length. In a unit with 2 years cycle length, this improvement will increase cycle length to more than 3 years.
b. SOR temperature will be lowered by about 5xc2x0 C. to 6xc2x0 C. (9xc2x0 F. to 11xc2x0 F.), which is equivalent to about a 2 to 3 month increase in cycle length, depending upon the deactivation rate of the catalyst.
c. Catalyst Activity, measured in delta temperature required, will be improved by about 1xc2x0 C. (1.8xc2x0 F.) to 1.5xc2x0 C. (2.7xc2x0 F.) for every 10 psi (0.7 kg/cm2). Therefore, with a 312 psi (21.9 kg/cm2) increase in hydrogen partial pressure, the total improvement will be about 30xc2x0 C. (54xc2x0 F.) to 35xc2x0 C. (63xc2x0 F.) in average bed temperature.
All of these factors are related, but not cumulative, and the total increase in cycle life for a 2-year cycle length unit will be about one year in the cycle length for the unit. Thus a 50% increase in production is achieved.
4. Heavier Feed Processing Capability
Increasing the hydrogen partial pressure enables the unit to run more heavy feed. For example where the hydrocracker feed is limited to 15% DMO 85% VGO under prior art conditions, this percentage can be increased with the higher hydrogen partial pressure obtainable through the practice of the invention. While the particular catalyst employed will have an effect on the quantity of the increase, a minimum increase of about 5% in DMO processing capacity, i.e., 20% DMO 80% VG, can be expected.
5. Higher Conversion Capability
With the improved hydrogen partial pressure, the hydrocracker conversion can increase from 96% to 98%. Additionally, poly-nuclear aromatics (PNA) build-up will be reduced and consequently the drag stream will be less.
6. Prevention of Coke Formation
The tendency to form coke is substantially reduced with an increase in hydrogen partial pressure in the reactor. Availability of more hydrogen reduces the hydrocarbon condensation in catalyst pores and subsequent plugging of the active sites on the catalyst.
7. Improved Feed Distribution Over Catalyst Bed
With higher hydrogen partial pressure feed distribution is substantially improved due to lower molecular size of gases which, in turn significantly reduces flow maldistribution and formation of hot spots in the reactor.
As will be apparent to one of ordinary skill in the art from the above analysis, the financial benefits associated with the practice of the invention are also significant. For example, a typical hydrocracker with a rated capacity at 30,000 BPD can achieve an improvement in total annual revenues from the incorporation of over $17 MM/yr in current dollars by adopting the process of this invention.